It is well known that the earth's crust contains underground fluid reservoirs. These reservoirs form an important natural resource for major components of our economic systems, e.g. oil, gas, water, etc. Recovery of resources from hydrocarbon reservoirs traditionally averages well below complete recovery, and on average only about 30–35% of the total resource in any given reservoir. Given the importance of oil and gas in our present day economy, an increased recovery of the total resources from oil and gas reservoirs is a major focus of many firms in this industry.
Recovery of these resources is dependent, in part, on knowing the “plumbing” of the reservoirs, i.e. the paths through which the fluid moves and by means of which the fluid can be extracted. In a fluid reservoir the “plumbing system” includes a network of interconnected cracks (“crack network”) that can be described as “hydraulically linked,” i.e. changes in fluid pressure can be transmitted through them. The character of the hydraulically linked crack network is known as the “reservoir permeability field.” Character, as used herein, refers to the shape and distribution of the crack network and the ease with which fluid moves through the network. Determining the character of reservoir permeability fields is the focus of much effort of fluid resource recovery and exploitation. For example, in a resource exploration and production application, the spatial geometry and the variation in flow of the permeability field are major factors in identifying locations and developing drilling plans and strategies for production wells that will yield enhanced production. In the case of hydrocarbons, injector wells are often used to enhance output of production wells. Injector wells are used to inject fluids whose densities differ from that of the hydrocarbons, and thus act to “sweep” the fluid that remains after the initial production phase. A more detailed knowledge of the reservoir permeability field would facilitate more efficient secondary and tertiary recovery in such applications.
Traditional approaches to determining the spatial geometry of permeability fields include the use of “guess and test” methods using reservoir simulators. A “guess and test” method uses largely inferential and sparse information about the permeability field to make a best “guess” as to its full three dimensional character. The “guess” is then “tested” by using measured data on production and injection from the field to test whether the model reproduces the measured data. The efficiency of “guess and test” methods is generally poor, and results in low quality of information relating to the reservoir permeability field.
Some approaches have attempted to determine the spatial geometry of permeability fields by seismic investigations of the geological medium. Such seismic investigations include measurements of time-limited (narrow-time window) determinate signals from artificial or natural sources. It has long been recognized that production from fluid reservoirs can induce seismicity. Attempts have been made to use microseismicity induced by production to gather information regarding fracture systems or the crack network, as well as other information, such as, for example, possible causes of the earthquakes, e.g. pore collapse, fault reactivation, etc. With few exceptions monitoring of this microseismicity has been done with seismometers placed “downhole” in wells adjacent to the study well in order to get as close as possible to the ruptures associated with fluid injection. The “downhole” method is both difficult and expensive to use as it requires either that an appropriate well be available or else that one be drilled. Further the use of downhole seismometers limits observations to within a few hundred meters of the observation well.
Another approach to determine the spatial geometry of permeability fields is described in U.S. Pat. No. 6,389,361, issued on May 14, 2002, which is incorporated by reference herein in its entirety. This patent describes increasing fluid pressure to generate a pressure “wave” at a point in the earth's crust to induce microseismicity and creep in the permeability field and to record this microseismicity and creep to create a map of the permeability field associated with the point of fluid pressure increase. The fluid pressure generates microseismicity and creep because the earth's crust is at a near critical state and responds to small changes in the ambient stress state. The permeability field mapped is close to an actual map of the permeability system. The induced microseismicity extends for kilometers from the point of fluid pressure change. The described mapping technique measures one component of the permeability field, namely the geometry.
In addition to the foregoing, the following sets of observations on secondary hydrocarbon recovery, hydraulically conductive fractures and microseismicity, are of particular importance with regard to the background of the present invention.                1. Rate correlation statistics, maximum compressive directions and rapid response: Heffer et al, (1997, Novel techniques show links between reservoir flow directionality, earth stress, fault structure and geomechanical changes in mature waterfloods, SPE Journal, V. 2, June, pp. 91–98) show that rate of production correlation's between producer and injection wells is directly related to the orientation of the maximum ambient compressive stress direction. Positive correlations (i.e. production increases) are observed between injection and production wells where the line connecting the two wells lies within a sector of arc of from 60 to 90 degrees that is bisected by the local maximum compressive stress. Response times between injector and producer wells has “zero” (less than 1 month) time lag over very large distances (>4.5 kilometers). They note that D'arcyian type diffusive flow cannot explain this phenomena.        2. Hydraulically conductive fractures are critically stressed: Barton et al (1995, Fluid flow along potentially active faults in crystalline rock, Geology, V. 23, no. 8, p. 683–686) demonstrate that critically stressed faults and fractures are those with the highest hydraulic conductivity and that statistically these are conoidally distributed around the maximum stress direction (Barton et al, 1995; FIG. 3).        3. Seismicity induced by fluid pressure changes shows rapid response over large distances: In the earthquake control experiment run at Chevron's Rangely, Colo. field and reported by Raleigh et al (1976, An experiment in earthquake control at Rangely, Colo.; Science, V. 191, p. 1230–1237), microseismicity induced by fluid injection and occuring at distances of up to 3 km from the injection well, were observed to stop within 1 day of shut-in of the injection wells.        4. No lower threshold for earthquake triggering and rupture size: A study of central California seismicity by Ziv and Rubin (2000, Ziv, A. and Rubin, A. M., Static stress transfer and earthquake triggering: No lower threshold in sight?, J. Geophys. Res., 105, B6, 13631–13642) finds no lower limit for the cumulative stress changes at the time of rupture. Further that the time delay between events is proportional to the magnitude of the stress change. This is consistent with the inverse power law relationship between the frequency of rupture events and their magnitude. Thus one may infer that the frequency of events increases as the rupture size decreases and there is no lower limit for rupture size.        
None of the above, however, provides sufficient useful information regarding the character of the hydraulically linked crack network. Thus, is would be desirous to develop systems and methods which provide useful information regarding the character of the hydraulically linked crack network.